Triple Cycle Power Plant

ABSTRACT

Abstract: A refrigeration cycle is integrated into a combined cycle power plant to form a triple cycle power plant in which gas turbine generator inlet air is chilled and dehydrated to increase the mass flow of the inlet air, and in which duct firing in HRSG is increased in dependence of the increased mass flow. In further preferred integration aspects, the heat from the inlet chiller refrigerant is provided to the HRSG.

FIELD OF THE INVENTION

Configurations and methods for combined cycle power plants.

BACKGROUND OF THE INVENTION

In a typical Brayton cycle, the output from the combustion turbinegenerator (CTG) becomes significantly less at high ambient temperatures.This output reduction is a major financial drawback of the simpleBrayton cycle or combined cycle power plant, as the power demand is highin summer. Inlet air cooling for open Brayton cycle configurations toincrease net power output is well known in the art. However, in manycases the temperature of the inlet air must be kept above the dew pointof the inlet air to avoid condensation, or even freezing out of thewater contained in the inlet air. To avoid at least some of the problemsassociated with condensation during cooling, numerous improvedconfigurations have been developed. For example, a freezing pointdepressant (which may also absorb water) may be sprayed onto the heatexchanger as described in U.S. Pat. No. 3,788,066 to Nebgen, or in U.S.Pat. No. 5,203,161 to Lehto.

Air inlet cooling systems and configurations were also adapted for usein combined cycle power plants, and an exemplary configuration isdescribed in U.S. Pat. No. 6,058,695 to Ranasinghe et al. Here adistillation/condensation subsystem is coupled to a chiller system thatcools the inlet air using the working fluid of the subsystem. While theinlet cooling of the '695 patent has various advantages, certaindifficulties nevertheless remain. Among other things, Ranasinghe'ssystem is typically limited to Kalina bottoming cycle configurations.Similarly, an inlet cooling configuration is described in U.S. Pat. No.6,173,563 to Vakil et al. in which part of a multi-component workingfluid is evaporated in an heat recovery steam generator (HRSG) togenerate a vapor fraction, which is then separated from thenon-evaporated working fluid and condensed. The so generated condensateis subcooled and used as a refrigerant to cool the inlet air. Whilethermal efficiency of the '563 process is typically improved,components, maintenance, and operation of such cooling systems aregenerally cost-prohibitive when compared to the overall capital gain.

Therefore, while numerous configurations and processes for power plantsare known in the art, all or almost all of them, suffer from one or moredisadvantage. Thus, there is still a need for improved power plants, andespecially for improved combined cycle power plants.

SUMMARY OF THE INVENTION

The present invention is directed to a power plant configuration andmethods in which inlet air chilling is expanded and heat integrated witha combined cycle power plant. In especially preferred aspects, ductfiring in the HRSG is increased as a function of increased mass flow ofthe inlet air due to the expanded inlet air chilling to therebysubstantially improve power output. The rejected heat from the inlet airmay further be provided to the HRSG to increase the thermal and energyefficiency associated with the use of inlet chilling in a CTG.

In one aspect of the inventive subject matter, a triple cycle powerplant includes a refrigeration unit (preferably a vapor compressionrefrigeration unit) that is configured to cool inlet air for a gasturbine in an amount effective to increase mass flow of the inlet air,and to produce a heated refrigerant. An HRSG receives heat from theexhaust of the gas turbine, heat from a duct firing system, andoptionally heat from the heated refrigerant, wherein the HRSG furtherproduces steam for a steam turbine generator. A control circuit isoperationally coupled to the plant and configured such that duct firingis increased in dependence of the increased mass flow of the inlet air.

Particularly contemplated plants may further comprise a moisture removalsystem (preferably comprising a triethylene glycol contactor) thatremoves water from the inlet air, which is typically chilled to atemperature of less than 32° F., and most typically between about −15°F. to about −5° F. Consequently, in at least some aspects of theinventive subject matter, the increase in mass flow of the inlet air isat least 10%, and more typically at least 15% relative to a mass flowwithout refrigeration. In further preferred configurations, therefrigeration unit has a first and second stage, and includes a moistureremoval system that removes water from the inlet air at a positiondownstream of the first stage and upstream of the second stage.

Therefore, a method of operating a plant may include a step in whichinlet air for a gas turbine is cooled to increase mass flow of the inletair. In another step, duct firing in a heat recovery steam generator isincreased as a function of the increased mass flow of the inlet air,wherein the HRSG receives heat from the exhaust of the gas turbinegenerator and produces steam for a steam turbine generator.

Various objects, features, aspects and advantages of the presentinvention will become more apparent from the following detaileddescription of preferred embodiments of the invention.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is an exemplary schematic configuration of a triple cycle powerplant.

DETAILED DESCRIPTION

The inventor discovered that inlet air chilling can be expanded to amuch cooler target chilled temperature and heat integrated with acombined cycle power plant in an economically attractive manner. Inespecially preferred aspects, duct firing in the HRSG is increased as afunction of the increased mass flow of the inlet air due to the expandedinlet air chilling to thereby substantially improve power output. Therejected heat from the inlet air may further be provided to the HRSG toincrease the thermal and energy efficiency associated with the use ofinlet chilling in a CTG.

An exemplary triple cycle power plant configuration is depicted in FIG.1 in which plant 100 has a combustion turbine generator 120 thatreceives chilled and dehydrated air 102′ from expanded inlet airchilling system 110. The moisture that is contained in the uncooledinlet air 102 is removed using moisture removal system 130, which isoperationally coupled to the expanded inlet air chilling system 110.Combustion turbine exhaust 104 passes through heat recovery steamgenerator 140, which generates high-pressure steam for steam turbinegenerator(s) 150. A duct firing control system 160 controls the ductfiring to the HRSG 140 in dependence of the increased air flow to thecombustion turbine generator 120 via control circuit 162, heat rejectedfrom inlet air 102 is further used as a heat source in HRSG 140 viaintegration loop 142.

With respect to contemplated plants, it should generally be appreciatedthat all plants are deemed suitable that have a combustion turbine witha heat recovery unit, and especially a heat recovery steam generatorcoupled to a steam turbine generator. Therefore, particularlycontemplated plants include combined cycle power plants. While notlimiting to the inventive subject matter, it should be appreciated thatcontemplated triple cycle configurations are especially advantageouswhere a plant is located in an environment subject to seasonal changesin temperature and/or humidity. However, contemplated plants alsobenefit from the configurations presented herein where seasonal changesin temperature and/or humidity are less significant. Furthermore, it iscontemplated that integration of the third cycle (vapor compressionrefrigeration or other) may be done as a retrofit to an existing plantor as an integrated triple cycle plant.

Especially preferred inlet cooling systems provide inlet air chilling toa temperature that is at least 10° F., more typically at least 20° F.,even more typically at least 40° F., and most typically at least 70° F.below ambient temperature to increase mass flow to the gas turbinegenerator. Therefore, contemplated inlet air temperatures after inletair cooling will be less than 45° F., more typically less than 32° F.,even more typically less than 20° F., and most typically less than 0° F.(e.g., between about −15° F. to about −5° F., but preferably above −25°F.). Depending on the particular refrigeration temperature, it iscontemplated that the increase in mass flow of the inlet air is betweenabout 5% and 10%, more preferably between about 10% and 20%, even morepreferably at least 15%, and most preferably at least 20% (calculatedrelative to a mass flow without inlet air refrigeration). There arenumerous configurations and methods for air refrigeration known in theart, and all of them are deemed suitable for use herein. However, inparticularly preferred aspects, inlet air refrigeration is performedusing vapor compression refrigeration with a single refrigerant or arefrigerant mixture.

Especially preferred vapor compression refrigeration systems includethose in which a first chiller cools inlet air to a first reducedtemperature (which is then preferably dehydrated in a moisture removalsystem), and in which a second chiller further cools the dehydrated andpre-cooled inlet air to a target inlet temperature. Therefore, in atleast some of contemplated aspects, a moisture removal system is locateddownstream of a first chiller and upstream of a second chiller.Alternatively, alternative cooling systems may be employed having asingle cooling stage or more than two chillers. For example, where thecombined cycle power plant is operationally coupled (or proximal) to aplant in which significant refrigeration capacity is available (e.g.,from LNG (liquefied natural gas) liquefaction or expansion of highpressure natural gas), the inlet cooling system may include multiplechillers.

Where desired, it is contemplated that the heat rejected from the inletair and/or from the compressed refrigerant may be transferred to varioussinks, and particularly suitable heat sinks include various low-heatheat sinks, boiler feed water from vacuum condensate pumps, etc.Alternatively, the heat may be disposed of in a cooling tower.

Moisture removal systems may be placed at any position upstream of theturbine inlet, however, it is generally preferred that the moistureremoval system is positioned between the first and second chiller stage.There are numerous moisture removal systems known in the art, and all ofthose are deemed suitable for use herein. For example, dehydration ofthe inlet air may be performed using adsorption (e.g., using molecularsieves), spraying of a hygroscopic solvent onto a chiller surface, orusing a solvent based absorption process. However, it is especiallypreferred that the moisture removal system comprises a triethyleneglycol-based (TEG) system. Such TEG systems are well known in the artand achieve water removal at relatively high efficiency using relativelylow amounts of energy.

Depending on the uncooled inlet air moisture content and temperature,and the desired cooled inlet air temperature, the configuration andcapacity of contemplated dehydration units may vary considerably.However, it is generally preferred that the cooled inlet air has atemperature and moisture content such that the cooled inlet air is at atemperature above the dew point, and most typically between about 5-10°F. above the dew point.

With respect to contemplated combustion turbine generators and steamturbine generators, it should be recognized that all known combustionturbine generators and steam turbine generators are suitable for useherein. However, especially preferred generators include those employedin combined cycle power plants that generate at least 10 MW, and moretypically at least 100 MW output. Similarly, contemplated HRSG includeall known HRSGs so long as such steam generators allow for duct firing.While in some of contemplated aspects conventional duct firing may beappropriate, modifications to the HRSG may be made to increasetemperature and/or pressure ratings due to the increase in duct firing.However, without the expanded inlet air chilling system resulting inhigher exhaust mass flows from the combustion turbine, the increase inthe HRSG temperature rating required for high levels of duct firingwould lead to prohibitive HRSG capital costs primarily due to the designtemperature limits of cost competitive, conventionally used tubematerials.

It should generally be appreciated that the increase in duct firing maybe controlled in numerous manners, and that all known manners of ductfiring control are considered appropriate herein. For example, where theincrease in mass flow results in a decrease in the HRSG temperature, theincrease in duct firing may be controlled via automatic temperaturecontrol. On the other hand, and especially where the plant is located inan environment with relatively small changes in inlet temperature and/orhumidity, it is also contemplated that the increase in duct firing maybe predetermined and manually set by an operator.

Therefore, the inventors generally contemplate a triple cycle powerplant comprising a refrigeration unit that is configured to cool aninlet air for a gas turbine generator in an amount effective to increasemass flow of the inlet air and to produce a heated refrigerant. A heatrecovery steam generator is coupled to the gas turbine and receives heatfrom the exhaust of the gas turbine generator, heat from a duct firingsystem, and optionally heat from the heated refrigerant, wherein theheat recovery steam generator produces steam for a steam turbinegenerator. A control circuit in such plants is further included andconfigured such that duct firing is a function of the increased massflow of the inlet air (typically: duct firing is increased withincreased inlet air cooling).

Consequently, a method of operating a triple cycle plant will thereforeinclude one step in which inlet air for a gas turbine generator iscooled to thereby increase the power output from the combustion turbineand the mass flow of the inlet air. In another step, duct firing in aheat recovery steam generator is increased as a function of theincreased mass flow of the inlet air (typically: duct firing isincreased with increased inlet air cooling), and in yet another step,steam is produced in a heat recovery steam generator that receives heatfrom an exhaust of the gas turbine generator and also part of heatrejected from the chilled inlet air.

EXAMPLE

The following example for a triple cycle configuration was based on acombined cycle (CC) power plant employing two GE 7FA combustion turbinegenerators (CTG's) and one GE D11-type steam turbine generator (STG)with HRSG duct firing. An expanded inlet air chilling system (EIACS) wasconfigured to chill the combustion turbine inlet air to −10° F. ATEG-based moisture removal system (MRS) was added to avoid icing at thecompressor inlet. Heat integration was further based on both, high CTGexhaust mass flow (and with that increased duct firing) and use ofrejected heat from the EIACS.

The performance of the EIACS and the MRS were evaluated with HYSYSmodels developed to simulate the selected configurations. Otherpublished design data were also used where applicable. GT-PRO/MASTER wasused to analyze the benefits of heat integration schemes. Allevaluations are based on preliminary specifications of designparameters, and it should be appreciated that the performance and/oreconomics may vary with varying process parameters.

Expanded Inlet Air Chilling System

In the present example, the expanded inlet air chilling system had twoair chillers, Chiller I and Chiller II. Chiller I was essentially thesame as a conventional GE 7FA CTG inlet chiller, which was configured tocool the inlet ambient air typically to 45° F. The air conditions werespecified as: 90° F. dry bulb, 76° F. wet bulb, and 0 feet elevation.The 45° F. inlet air generated by Chiller I then flowed to one of theTEG contactors of MRS where the moisture content was reduced (infra).Chiller II then cooled the dehydrated air to −10° F. before entering thecombustion turbine compressor. It should be appreciated that bothChillers I and II can be integrated with the combined cycle plant toimprove efficiency and to lower capital costs, especially when therequired compressors are commercially available as off-the-shelfdesigns.

Ambient conditions were set to 90° F. dry bulb and 76° F. wet bulb atzero elevation. Using these parameters, GT Master calculated 3,260,000lbm/hr inlet air flow and 149 MW net output from a GE 7FA CTG without aninlet air chiller. In contrast, with EAICS chilling the inlet air to−10° F., both the inlet air flow and output increase to 3,920,000 lbm/hrand 190 MW respectively. Thus, the EIACS provides about 82 MW additionalCTG output from a 2×1 7FA combined cycle plant.

Based on various HYSYS model calculations, the EIACS options consumedfrom about 22 MW to 32 MW (depending on the efficiency of the selectedEIACS), thus providing a net additional output of 50 MW to 60 MW fromthe two 7FA CTGs. Moreover, the EIACS also generates much higher exhaustmass flows enabling higher STG output from higher allowed levels of HRSGduct firing as discussed below in the section entitled “Duct Firing”.

Moisture Removal System

The moisture removal system (MRS) included a triethylene glycol (TEG)contactor and a TEG Regenerator Unit (TRU). The TEG contactor wasconfigured as a bed of structure packing in which the CTG inlet airflows upward in countercurrent with TEG flowing downward through thepacking. The TRU regenerates the water-rich TEG from the contactor bywater vaporization and continuously supplies the regenerated TEG back tothe contactor. Stripping gas may be needed for the conventional designof the TRU if higher than 98.5 weight % of regenerated TEG is required.However, a number of designs are also known in the art to achieve 99.99weight % TEG without stripping gas. In most calculations, the MRS wasset to reduce the moisture content of the 45° F. chilled air fromChiller I to a dew point of −25° F.(0.0002 lbm of water/Ibm of dry air).As the target chilled air temperature for Chiller II is −10° F., the dewpoint of −25° F. allows −15° F. margin to account for potential airtemperature drops due to higher velocities at the compressor intakenozzle.

A HYSYS model was developed to simulate the performance of the MRSrequired to reduce the inlet air from a moisture content of 0.0063 lbwater/lb of dry air (45° F. Saturated) to 0.00019 lb water/lb of dry air(−25° F. dew point). With a concentration of 99.9 weight percent for theregenerated TEG supplied by the TEG regeneration unit, HYSYScalculations indicated that about 1070 gpm of regenerated TEG wererequired to reduce the 3,920,000 lbm hr inlet at 45° F. saturated to adew point of −25° F. The HYSYS models also indicated that, at 1070 gpmof regenerated TEG, a total of six theoretical “mass-transfer” stageswere required in the TEG contactor.

It should be recognized that although TEG has been widely used for dewpoint control of natural gas, TEG has not been commercially used formoisture removal of inlet air to 7FA gas turbines. Nevertheless, all ofthe published data for natural gas seem to suggest that 99.9 wt % TEG isadequate to reach an air dew point of −25° F. (higher concentration ofregenerated TEG will reduce the required rate of TEG circulation, thenumber of theoretical stages, and the required capacity and capital costof the required regeneration units). Furthermore, it was calculated thatthe total air side pressure drop of the TEG contactor will decreaseoutput by about 0.36 MW for every inch water of pressure drop in CTGinlet at −10° F. For example, using a 15 ft contactor bed depth locatedin the extended air duct scheme, the total pressure drop across theextended air inlet duct, the TEG contactor, and second chiller coil isabout 4.5 inches of water. This pressure drop was calculated using acorrelation provided by the packing vendor and loss coefficientspublished by ASHRAE. As the total inlet pressure drop for GE 7FA withinlet chilling to 45° F. is typically 4 inches of water, the new totalpressure drop including all of the triple cycle features is about 8.5inches of water.

Duct Firing

Relative to ambient condition of 90° F., the −10° F. chilled airtemperature increased the CTG exhaust mass flow by about 20%. Thishigher mass flow allowed a significantly higher level of HRSG ductfiring without exceeding the temperature limits of commonly used HRSGtube materials. To explore the potential benefits of the EIACS on theSTG output, GT-Master runs using a model with typical/conventional 2002HRSGs designed for a duct-fired CC plant employing two GE 7FA combustionturbines and 300-330 MW D11 STG were performed. Among other things, theresults showed that chilling the CTG inlet air to −10° F. from ambientconditions of 90° F. dry bulb/76° F. wet bulb allows duct firing toreach the ultimate capacity of 405 MW for the D11 STG.

The inlet orifice areas of the STG model have been adjusted primarily tomaintain HP inlet pressure of about 1927 psia. The calculated ductfiring temperature is 1784° F., which is within maximum firing limit oftypical/conventional 2002 HRSGs which have a normal firing temperatureof 1763° F. (e.g., DENA HRSG). Where needed, water wall features forhigh duct firing temperatures may be employed. Under typical operatingconditions, duct firing to 405 MW STG output was calculated not toexceed HRSG duct firing limits.

Recovery of Heat from Chillers

Heat integration in the exemplary calculations also included use of thecondensate and/or feed water from the vacuum condensate pumps tocondense the refrigerant in the chiller condensers. Thus, it should berecognized that the heat rejected from the EIACS will be recovered inthe condensate before flowing back to the HRSGs, which is thought toreduce or even eliminate the need for a chiller cooling tower (and theassociated chiller cooling water pumps). Therefore, recovery of heatrejected from the chillers improves overall plant efficiency and reducesthe net plant heat rate. It should be recognized that the particularextent of heat rate reduction will depend on the particular choice ofrefrigerant for the chillers and/or the associated operationalparameters (e.g., cooling water supply temperature and the terminaltemperature difference (TTD) of the condenser) of equipment in thebottoming cycle.

Primarily because of the increased HRSG duct firing level, the net plantheat rate for the 405 MW STG output reaches about 7324 BTU/kWh. Thisrate may be further lowered by recovering heat rejected from the EIACSto the bottoming cycle. To transfer the heat from the chiller condensersto the condensate from the steam surface condenser, the refrigerantcondensing temperature range must be adequately higher than thetemperature range of the condensate being heated. Refrigerant condensingtemperatures may be increased without a reduced efficiency primarily byselecting certain types of refrigerant mixtures. Alternatively, oradditionally, refrigerant condensing temperatures can also be increasedby raising the supply temperature of the cooling medium, which willincrease the power consumption of chiller and reduce the coefficient ofperformance (COP). In still further contemplated aspects, the condensatetemperature or the STG exhaust steam condensing temperature can belowered to some extent allowing recovery of heat rejected from thechillers, which will reduce the heat rate and increase the STG output.

At ambient conditions of 90° F. dry bulb and 76° F. wet bulb, the EIACSwith −10° F. target chilled air temperature was calculated to generateabout 400 MMBTU/hr of relatively low temperature heat, typicallyrejected to the chiller cooling tower. For the bottoming cycleconfigurations of a typical/conventional, 2002 combined cycle (CC) plantwith 2 GE 7FA CTGs operating at 90° F. dry bulb and 76° F. wet bulb,duct firing the HRSGs to generate 405 MW STG yielded a condensatetemperature of about 135° F., which is about the typical maximum exhausttemperature limit for D11 STG.

Relative to a typical CC plant design with HRSG duct firing in 2002,duct firing to 405 MW STG corresponded to a 36% increase on thebottoming cycle capacity (roughly about 138% additional STG outputrelative to the similar plant without HRSG duct firing). The net plantheat rate of 7324 BTU/kWh can be further lowered by expanding thebottoming cycle capacity to a net plant heat rate of 7224 BTU/kWhoperating at the same design ambient conditions of 90° F. dry bulb and76° F. wet bulb. Thus, based on our calculations, expanded bottomingcycle reduced the heat rate by about 100 BTU/kWh. Heat integration stillfurther reduced the heat rate to 7146 BTU/kwh. A net heat reduction ofabout 75 BTU/kWh can be attained when the 104° F. condensate temperatureis increased to 153° F. by recovering the some of the rejected heat fromthe EAICS using refrigerant mixtures such as 20% R-170, 20% R-290, and60% R-600 in Chiller I and 1% R-170, 70% R-290, and 29% R-600 in ChillerII.

Thus, specific embodiments and applications of triple cycle power plantshave been disclosed. It should be apparent, however, to those skilled inthe art that many more modifications besides those already described arepossible without departing from the inventive concepts herein. Theinventive subject matter, therefore, is not to be restricted except inthe spirit of the appended claims. Moreover, in interpreting both thespecification and the claims, all terms should be interpreted in thebroadest possible manner consistent with the context. In particular, theterms “comprises” and “comprising” should be interpreted as referring toelements, components, or steps in a non-exclusive manner, indicatingthat the referenced elements, components, or steps may be present, orutilized, or combined with other elements, components, or steps that arenot expressly referenced.

1. A triple cycle power plant comprising: a refrigeration unitconfigured to cool an inlet air for a gas turbine generator in an amounteffective to increase mass flow of the inlet air and to produce a heatedrefrigerant; a heat recovery steam generator that receives heat fromexhaust of the gas turbine generator, heat from a duct firing system,and optionally heat from the heated refrigerant, wherein the heatrecovery steam generator produces steam for a steam turbine generator;and a control circuit that is configured such that duct firing is afunction of the increased mass flow of the inlet air.
 2. The triplecycle power plant of claim 1 wherein the refrigeration unit comprises avapor compression refrigeration unit.
 3. The triple cycle power plant ofclaim 1 further comprising a moisture removal system that removes waterfrom the inlet air.
 4. The triple cycle power plant of claim 3 whereinrefrigeration unit comprises a vapor compression refrigeration unit andwherein the moisture removal system comprises a triethylene glycolcontractor.
 5. The triple cycle power plant of claim 1 wherein thecooled inlet air has a temperature of less than 32° F.
 6. The triplecycle power plant of claim 1 wherein the cooled inlet air has atemperature of between about −15° F. to about −5° F.
 7. The triple cyclepower plant of claim 1 wherein the refrigeration unit is configured toincrease mass flow of the inlet air at least 10% relative to a mass flowwithout refrigeration.
 8. The triple cycle power plant of claim 1wherein the refrigeration unit is configured to increase mass flow ofthe inlet air at least 15% relative to a mass flow withoutrefrigeration.
 9. The triple cycle power plant of claim 1 wherein therefrigeration unit comprises a first stage and a second stage, andwherein a moisture removal system that removes water from the inlet airis downstream of the first stage and upstream of the second stage. 10.The triple cycle power plant of claim 9 wherein the refrigeration unitis configured to increase mass flow of the inlet air at least 15%relative to a mass flow without refrigeration.
 11. A method of operatinga plant comprising the steps of: cooling inlet air for a gas turbinegenerator to increase mass flow of the inlet air; increasing duct firingin a heat recovery steam generator, wherein the increase in duct firingis a function of the increased mass flow of the inlet air; and producingsteam in a heat recovery steam generator that receives heat from anexhaust of the gas turbine generator.
 12. The method of claim 11 whereincooling is performed using a refrigerant to thereby produce a heatedrefrigerant.
 13. The method of claim 12 wherein the heat recovery steamgenerator further receives heat from the heated refrigerant.
 14. Themethod of claim 11 wherein the inlet air is cooled below a dew point andwherein a moisture removal system removes water from the cooled inletair.
 15. The method of claim 14 wherein cooling is performed using avapor compression refrigeration unit, and wherein the moisture removalsystem comprises a triethylene glycol contactor.
 16. The method of claim11 wherein the inlet air is cooled to a temperature of less than 32° F.17. The method of claim 11 wherein the inlet air is cooled to atemperature of between about −15° F. to about −5° F.
 18. The method ofclaim 11 wherein the inlet air is cooled to increase mass flow of theinlet air at least 10% relative to a mass flow without refrigeration.19. The method of claim 11 wherein the inlet air is cooled to increasemass flow of the inlet air at least 15% relative to a rnass flow withoutrefrigeration.
 20. The method of claim 19 wherein the inlet air iscooled in a refrigeration unit that has a first stage and a secondstage, and wherein a moisture removal system that removes water from theinlet air is downstream of the first stage and upstream of the secondstage.